In June 2010, the US Department of Energy (DOE) selected a
gas-specialty company to receive American Recovery and
Reinvestment Act (ARRA) funding to design, construct and
operate a system to capture CO2 from two steam
methane reformers (SMRs) located within the Valero refinery in
Port Arthur, Texas. The CO2 removal technology will be retrofitted to
the SMRs, which produce hydrogen to assist in the manufacture
of petrochemicals and the making of
cleaner burning transportation fuels by refinery customers on
the Gulf Coast hydrogen pipeline network.

The necessary commercial agreements were signed to proceed
with a planned carbon capture and sequestration
(CSS) project in Port Arthur, Texas. The refinery is providing the additional
land and rights-of-way required for the project, in addition to
supplying utilities to support the project. Meanwhile, purified
and compressed CO2 will be supplied for injection
into enhanced oil recovery (EOR) projects in Texas. CO2
for EOR is beneficial because it:

Increases energy security by increasing recoverable
oil

Creates economic opportunity for the government via
increased tax revenues and for individuals via jobs created
in domestic oil fields.

Provides environmental benefits from
capturing, productively using and storing CO2,
rather than emitting it into the atmosphere.

Beginning in late 2012, approximately 1 million tons of
CO2 annually will be recovered and purified. The DOE
is providing a total of $284 million or approximately 66% of
the over $400 million project. This includes partial
reimbursement of operating costs through the end of the
demonstration period (September 30, 2015).

Objectives and scope

The main objective for this CO2 capture project
is to demonstrate an advanced technology that captures and
sequesters carbon dioxide emissions from large-scale
industrial sources into underground formations. In order to be
eligible for supplemental funding from the DOE, it was
necessary for applicants to meet certain DOE objectives, which
are itemized in Table 1.

In addition, the DOE evaluated projects on a cost-per-unit
basis of CO2 captured and sequestered, as well as on
the magnitude of future potential commercialization. This
project will provide real-world data illustrating the true
costs of CO2 capture and sequestration. It was one
of only three projects to receive Phase 2 funding from the DOE,
which covers construction and operating and maintenance costs during the
demonstration period.

Current Port Arthur site

A new 180-mile-long pipeline is being constructed to connect
to existing Louisiana and Texas hydrogen pipeline systems. This
integrated pipeline system will unite over 20 hydrogen plants
and over 600 miles of pipelines to supply the Louisiana and
Texas refinery and petrochemical industries with more
than one billion cubic feet of hydrogen per day. The Port
Arthur SMRs and the CO2 capture project will be part
of the combined pipeline system (Fig.
1).

Fig.
1. The CO2 capture project will be
part
of a hydrogen pipeline system on the US Gulf
Coast.

The Port Arthur site was selected to host the CO2
capture facility based on economies of scale of capturing
CO2 from the two SMRs on the premises. The proximity
of the SMRs accommodated a common drying and compression system
that significantly reduced capital when compared to the
alternative of isolated drying and compression
arrangements.

Fig.
2. 1 million tons of CO2 per
year will be captured from the two SMRs. The
CO2 will be used for enhanced oil
recovery.

Process summary and equipment

Fig. 3 is a block flow diagram for the
project that illustrates how the CO2 capture
facility will be integrated within the existing SMRs. The
facility will utilize a proprietary-designed CO2
vacuum swing adsorption (VSA) system that will be retrofitted
to each of the two existing SMR trains (PA-1 and PA-2). Each
VSA unit is designed to remove more than 90% of the
CO2 contained in the reformer pressure swing
adsorption (PSA) feed gas (Fig. 4). Sweet
syngas (CO2 removed) will be returned from the
CO2 VSA system to feed the existing SMR hydrogen
PSAs. CO2 produced from the VSA units will be
compressed and dried in a single train located at PA-2.

Fig.
4. VSA trains are used to remove
more
than 90% of the CO2 contained in
the
reformer PSA feed gas.

VSA system (PA-1 and PA-2). CO2
containing syngas from the steam-methane reformer cold process
condensate separator is routed to the VSA system. The
CO2 contained in the process gas of the PA-1 and
PA-2 SMRs will be removed with multiple VSA units. Each VSA
unit includes a series of vessels filled with adsorbent to
selectively remove one or more components from the feed gas. In
this case, the feed gas is the raw hydrogen stream from the SMR
plants upstream of the existing hydrogen PSA.

The VSA cycle is similar to the hydrogen PSA cycle. Adsorber
vessels are fed with gas at high pressure, causing selective
adsorption of feed components onto the adsorbent bed. The gas
that is not adsorbed by the bed is a hydrogen-rich stream and
is sent to the H2 PSA for further purification.
Then, the vessel undergoes a series of pressure equalizations,
with vessels at lower pressures before a CO2 product
is drawn off. There are two unique steps in the VSA cycle
because the product is now CO2 at high purity. The
first is that a vacuum pump is needed to draw off the
CO2 product (Fig. 5) to
sub-atmospheric pressures in an evacuation step.
The second is a rinse step in which blowdown gas is
taken from a lower pressure bed, compressed, and fed to a
higher pressure bed. The rinse and
evacuation steps are the keys to achieving a high
purity CO2 product.

Fig.
5. VSA vacuum blowers are used to
recover CO2 from the VSA beds and
deliver
it to the CO2 product compressor
before
offsite transport via pipeline for use in
EOR.

CO2 compressor and dryer (PA-2).
Raw CO2 exits the two trains of the VSA systems
after cooling and is combined at the suction of the first stage
of an eight-stage, integrally-geared centrifugal compressor.
Each of the first five compressor stages is followed by an
intercooler, which also includes an integral separating section
to remove condensate, which is mainly water.

Condensate from the first five intercoolers is combined in a
common vessel and piped to the existing plant waste sump. A
portion of the PA-2 condensate can be sent to the tri-ethylene
glycol (TEG) dryer system, where it serves as water makeup,
thereby reducing the overall water requirements of the plant by
recycling.

CO2 exiting the fifth stage intercooler is sent
to a TEG drying system, where water is removed. After drying,
the CO2 is sent to the sixth stage section, where
the final compression occurs in stages 6, 7 and 8. After final
cooling following the eighth stage, the CO2 exits
the battery limits and enters the CO2 pipeline at
the required pipeline pressure of over 2,000 psig.

TEG dehydration units have routinely been used for
CO2 dehydration for EOR applications, as well as
being the standard technology for natural gas drying.
TEG has a very high affinity for water, allowing very high
removal, and a low volatility, minimizing solvent losses into
the CO2 product.

The wet CO2 exits the after cooler following the
fifth stage of compression and is contacted with lean dry TEG
in the tray or structured packing section of the contactor
tower, where water vapor is absorbed in the TEG, thus reducing
its water content. The dry CO2 exiting the top of
the absorber is heated vs. the incoming lean TEG and sent to
the final three stages of CO2 compression, where the
CO2 is raised above the critical pressure of 1,071
psia. The TEG content of the dry CO2 is very
low.

The wet rich TEG exiting the contactor is depressurized and
flows to the regeneration system. The wet rich TEG is then
preheated and flashed in a horizontal separator to remove much
of the dissolved CO2 and other light gases. The
flash gas is sent back to the compressor so that the contained
CO2 is not lost. The flashed water-rich TEG liquor
is cleaned in charcoal and sock filters and then heated with
lean TEG from the regenerator column. The rich heated TEG is
then fractionated in the regenerator column and heated in the
reboiler, boiling
off the absorbed water vapor. The lean TEG exiting the bottom
of the regenerator is cooled with rich TEG and then pumped back
to the absorber. The reboiler is directly
fired with natural gas.

The CO2 for EOR will be transported to the site
via the pipeline, and will be injected via a CO2
injection pump station in the field connected to 14
CO2 Class II injection wells.

The commercial monitoring program will track the
CO2 injected, the CO2 recycled and the
performance of the reservoir and wells in retaining
CO2. The research program will collect time-lapse
data testing alternative and possibly high-resolution
techniques for documenting that the CO2 is retained
in the injection zone and in the predicted flood area, and that
pressure is below that determined to be safe. A report will be
prepared evaluating the results of the MVA program, revised
model runs showing model match, comparing the effectiveness of
the commercial program to the research program in documenting
effectiveness and permanence of storage.

CO2 export pipeline

A 13-mile pipeline will be constructed in conjunction with
this project to connect the
CO2 capture facility with the Green pipeline. The
pipeline is an existing 24-in. pipeline that runs from
Donaldsonville, Louisiana, to the Hastings Field, south of
Houston, Texas (Fig. 6).

Current status

The CO2 capture project is being executed in
three phases and is proceeding right on schedule. Phase 1
established the definitive project basis and has been
completed. Phase 2 covers the design and construction of the project and
Phase 3 entails operation of the project through the end of the
demonstration period. The project is currently in Phase 2. The
project is further broken down into three sub-projects:
CO2 capture facility, CO2 export pipeline
and MVA. The CO2 capture facility and CO2
export pipeline are being executed as a single project, with
the MVA portion subcontracted to Denbury.

For the CO2 capture facility, all of the major
equipment purchases and detailed design have been completed.
The detailed design for work outside the battery limit (OSBL)
has been awarded and is complete. The OSBL construction work
was kicked off in the spring of 2011. For work inside the
battery limit (ISBL), piling began in August 2011 and
foundations began October 2011; both have been completed.
Mechanical construction began January 2012, and electrical and
instrumentation construction began June 2012.

The units are being brought online in sequence to facilitate
early CO2 capture and to allow for commissioning
learnings from PA-2 to be incorporated into PA-1. Commissioning
activities are planned for September 2012, with CO2
product being introduced in the pipeline December 2012.

Forward schedule and plan for the future

The PA-2 CO2 capture unit (including
CO2 drying and export compression) is scheduled to
be onstream in late 2012 and the PA-1 CO2 capture
unit is scheduled to be onstream in early 2013. The
demonstration period will continue until September 30,
2015.

Over the past 25 years, the industry has transitioned from
amine and potassium
carbonate liquid absorption
processes to PSAs for two reasons. The first is because of
increased hydrogen purity requirements for refining processes. The second
involves the increased thermal efficiency afforded by steam
export to refineries. Capturing CO2 from existing
hydrogen plants with PSAs is more challenging because the
thermal efficiency is already highly optimized. VSAs are
advantaged for retrofits because they can be more easily
incorporated with minimal impacts to hydrogen supply to the
existing refinery. This commercial scale
demonstration of VSA technology provides an additional option
for recovering significant volumes of CO2 for
EOR.

Despite a shortage of CO2 for EOR, the existing
CO2 market does not support current CO2
capture economics without external funding, which is why the
DOEs support is essential. Technical and economic results
from this project will be key in determining the most effective
path to commercialization. HP

NOTE

Air Products and Chemicals received the ARRA funding to
supply CO2 for EOR.

The authors

William F. Baade is the global
marketing manager for oil, natural gas and transport
fuels in Air Products Tonnage Gases, Equipment
and Energy Division. He has over 35 years of
industrial experience in various sales, business
development and marketing assignments. Mr. Baade
holds a BS degree in chemical engineering from
Stevens Institute of Technology and
graduated
in 1976. He obtained a MBA degree from Lehigh
University in 1982.

Sarah G. Farnand is a market manager
with Air Products & Chemicals. Her current
responsibilities include analyzing the global oil and
natural gas markets with an eye to identifying
opportunities for Air Products in the fields of EOR,
GTLs, LNG, refining and alternative
fuels. She holds a BA degree in economics from the
College of William and Mary and a MBA in finance and
strategy from the University of Maryland.

Robert L. Hutchison joined Air
Products & Chemicals in 1979 and is currently the
senior project manager for the Port Arthur
CO2 recovery project. Mr. Hutchison has
held various engineering, operations and commercial
positions during his 33 year career at Air Products
and has distinguished himself in the management of
large, complex industrial gas projects. He holds a BS
degree in chemical engineering from the University of
Illinois and a MBA degree from Lehigh University.

Ken Welch joined Air Products &
Chemicals in 1996 and is currently the HyCO business
development manager. Mr. Welch was the principal
investigator for the CO2 capture project,
working as the asset manager and primary contact for
the DOE. Mr. Welch has held various commercial
positions during his Air Products career and has
distinguished himself in the business development of
large, complex HyCO projects. He holds a BS
degree in chemical engineering and marketing from
Pennsylvania State University.

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I'm a huge advocate in the projects that will renew oilfields and create a greener environment. I would like and appreciate to know when construction is scheduled to begin in my area, Splendora, TX 77372. I look forward to your comments and hopefully a cool map with a layout.